Borehole Imaging Technology Visualizes Photorealistically in Oil-Based Muds

36 JPT • NOVEMBER 2014 To estimate reserves, optimize well recovery, and place future development wells more accurately, operators require increasingly detailed understanding of complex oil and gas reservoirs. Highresolution geological data from the borehole—core samples and wireline microresistivity images—are essential to fully characterize reservoir architecture, guide and constrain reservoir models, and make timely decisions with precision and confidence. In unconventional resource plays, for example, geologists need to observe complex natural fracture systems, measure fracture density and direction, determine in-situ stresses, and calculate pressures required to initiate and propagate optimal hydraulic fracturing. In high-cost deepwater environments, exploration teams need to interpret a wide variety of sedimentary facies. Reservoirs often consist of thinly laminated sands or channels, which demand highdefinition methods for visualization and interpretation. Typically, deepwater formations exhibit very low resistivities— from 1 ohm-m in shales to as low as 0.2 ohm-m in water-bearing sands. Operators often use whole cores to identify subtle sedimentary facies, but cores can be expensive and time-consuming to acquire. Thus, core samples are usually obtained only in select wells and in the most critical intervals. The resulting lack of geological detail can adversely affect reservoir analysis, interpretation, and modeling. On the other hand, microelectrical borehole images can be acquired continuously over the openhole interval at any depth or in any formation, with relative ease. Until recently, high-definition borehole imaging has been possible only in electrically conductive water-based muds (WBM). However, most deepwater wells and many unconventional shale wells today are drilled with high-performance, nonconductive oil-based muds (OBM). Legacy OBM borehole imaging tools, which were introduced in the last decade, are a significant technical advancement over the preceding dipmeter tools but still exhibit certain limitations. For example, spatial image resolution in OBM is nowhere near the quality obtained from WBM imagers. The lack of circumferential coverage of the borehole leaves large gaps that must be filled by inference. OBM imagers also rely on complex physics to measure formation resistivity beyond the nonconductive mud barrier. These may create geologically nonrepresentative artifacts such as shadow beds that hinder the visualization of formation geology. Largely because of electrode geometry, conventional OBM borehole imaging tools may have low sensitivity to features that run nearly parallel to the wellbore. Finally, the mechanical design of all existing borehole imaging tools allows them to record data only while exiting the hole. This limitation increases the occurrence and severity of stickand-slip, which adversely affects final image quality. For these reasons, geoscientists are often subject to uncertainties about reservoir texture, sedimentology, depositional environment, and important structural elements such as the recognition and orientation of faults and fractures. The industry has long recognized the need for an OBM-adapted imaging technology that can provide resolution and borehole coverage comparable to the best imagers in WBM environments.